Method of servicing high temperature wells

ABSTRACT

A method of servicing high temperature wells. A cooling chamber is secured in end to onto a wellhead of a high temperature well. A hot tubing string is raised from the high temperature well into the cooling chamber. A cooling fluid is injected into the cooling chamber to cool the hot tubing string prior to handling.

FIELD

The present method was developed to service high temperature wells without requiring them to be cooled prior to servicing.

BACKGROUND

There are currently a number of energy companies producing oil in Northern Alberta regions using steam-assisted gravity drainage (SAGD) recovery methods. As its name implies, SAGD production uses steam to elevate the temperature of the bitumen or heavy crude in the formation. Once the viscosity is reduced to a sufficient level, the fluids will freely flow, by gravity, to the well where they can be pumped to the surface. Temperatures typically encountered in SAGD operations are generally between 200° C. and 300° C. and pressures are generally between 2000 kPa 5500 kPa. Other wells aside from SAGD wells may also operate under similar high temperature and high pressure conditions. For example, with the toe heel air injection method (THAI) of producing bitumen, the temperature may be in excess of 600° C.

Conventional well servicing operations require that both the well temperature and the well bore pressure are reduced before work can proceed. In SAGD wells, the temperature of a particular well is reduced by shutting down the steam injection in the vicinity of the well to be worked over. Of course, once the steam is shut down, production in all of the neighbouring wells ceases until the reservoir temperature gets back up to producible levels. This is a lengthy process and it may end up being several months until the well is back in production. There are, therefore, considerable costs incurred with a well servicing operation; the cost of reheating the formation to producible levels as well as the loss of production during this period. In some cases, a number of wells are positioned in close vicinity to one another so as to support each other in heating the formation. In the event that one of these wells require servicing a number of wells could be affected by the prerequisite to cool one of the group's members. Again, several months of seriously impacted production could result; not to just one well, but to numerous wells.

What is required is a method to safely perform servicing operations on high temperature wells while they are operating within their normal temperatures and pressure ranges.

SUMMARY

There is provided a method of servicing high temperature wells, comprising the steps of securing a cooling chamber onto a wellhead of a high temperature well; raising a tubular member from the high temperature well into the cooling chamber; and injecting the cooling chamber with a cooling fluid to cool the hot tubing string prior to handling.

According to different aspects, the cooling chamber is defined by a stack of spools attached in end to end relation onto the wellhead. The tubular member may have a temperature of at least 100° C. or 200° C. prior to entering the cooling chamber. The tubular member may be cooled to a temperature of less than 50° C. in the cooling chamber. The tubular member may be continuously raised through the cooling chamber. The tubular member may be raised during a snubbing operation. The cooling chamber may have a cooling fluid input and a cooling fluid output for circulating cooling fluid through the cooling chamber. Injecting the cooling fluid may comprise maintaining the pressure of the cooling fluid in the cooling chamber at a pressure that avoids overbalancing the well. The cooling fluid may be in direct contact with the tubular member.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to be in any way limiting, wherein:

FIG. 1 is a side elevation view of a wellhead with a stack of spools forming a cooling chamber.

FIG. 2 is a top plan view in section of the cooling chamber.

DETAILED DESCRIPTION

The method will now be described with reference to FIGS. 1 and 2.

It is possible to maintain pressure and work on the well by cooling the tubular member, such as a tubing string or coiled tubing string, and pulling the tubular member through a closed BOP. The tubular member is cooled by a cool fluid or gas being pumped through a cooling chamber situated between the wellhead and the snubbing unit. For the purposes of this application, it will be understood that “fluid” means any substance, such as a liquid or gas, that can flow. For the purposes of this application, a high temperature well is considered anything with a temperature above that which can be safely handled by workers, such as 50° C. However, the method is designed primarily for use with high temperature wells that have a temperature of at least 200° C.

Referring to the embodiment depicted in FIG. 1, a SAGD well 10 is shown with a number of spools 12 bolted onto the wellhead 14. Referring to FIG. 2, spools 12 have an internal diameter that forms a cooling chamber 15. The cooling chamber 15 is large enough to receive the tubular body 16 as it is pulled through. While spools 12 are shown, it will be understood that other bodies could be used to form the cooling chamber, such as a large pipe, or other body that is large enough and has a cavity. Referring again to FIG. 1, the spools 12 are stacked end to end and allow the tubing string to pass through their centers. The height of the spool stack is determined by the amount of cooling required to bring the tubing string down to a temperature that can be handled safely. For example, temperatures above 50° C. are likely too hot to safely handle by workers. If more cooling is required to reach a safe operating temperature, more spools 12 may be stacked together give a larger area of tubing exposed to the cooling fluid or gas.

Above the stack of spools 12 is a snubbing unit 18. The snubbing unit blow out preventer stack 20 is bolted to the top most spool and keeps the pressure in the well from escaping to the atmosphere. The snubbing unit 18 provides a means of raising or lowering the tubing string in and out of the well while it is under pressure.

On each of the lowermost and uppermost spools 12, there is a port 22 so that a suitable gas or liquid can be pumped into the cooling chamber. The fluid is pumped into one port 22, flows up or down the stack of spools and out of the other port 22. The pressure is maintained on the outgoing line so that the fluid pressure in the spool stack is equal to or higher than the well pressure. This prevents the fluid from escaping down the well. The fluid enters into the spool system at a lower temperature than the tubing string and serves to cool it as it passes through the stack of spools. A number of variables can be adjusted to change the amount of cooling—the fluid used, the temperature of the fluid, the height of the spool stack, the speed at which the tubing string is pulled through the spool stack 12, and the flow rate of the fluid. By this means, tubing can be cooled as it is removed from the well by the snubbing unit 18. The pressure is maintained by the BOP system 20 and the well can be serviced without having to cool the well down. As the hot tubing string is extracted through the wellhead 14, it is exposed to the flow of cooling gas in the spool stack. The extraction rate of the tubing as well as other variables can be adjusted so that the tubing string comes out of the BOP 20 at a temperature that can be safely handled by the personnel on the snubbing unit.

In a preferred embodiment, the removal of production tubing results in intermittent movement of the tubing string as the various lengths are removed. Preferably, the cooling occurs quickly enough that the tubing string is cooled as it is pulled up through spools 12. This is particularly important if used with coiled tubing string, as it is pulled continuously.

In the depicted embodiment, the cooling chamber is open to the annulus of the well. In a preferred embodiment, a gas, such as nitrogen gas, may be pumped into the cooling chamber at the bottom port 22, and extracted at the top port. The nitrogen gas is pumped in at a pressure that is slightly higher than the wellbore pressure, and is allowed to escape through the top port 22. This creates a nitrogen gas buffer at the top of the wellbore. While there will generally be some gas that escapes downhole because of the higher pressure and the mixing of fluids, the rate of flow in and out of the cooling chamber may be monitored to ensure that this is minimized to an acceptable level. If it is found that an unacceptable gas is being diverted downhole, the pressure may be adjusted to reduce this. Other gases may be used, such as carbon dioxide, although nitrogen is preferred for economic reasons. For safety reasons, the gas should be an inert gas. While the fluid may be at any temperature below the target temperature, a colder fluid will accelerate the cooling process. However, excessively cold temperatures may cause certain components to freeze. To balance these concerns, a suitable temperature for the cooling fluid has been found to be within 3 or 4 degrees of 5° C.

In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one of the elements.

The following claims are to be understood to include what is specifically illustrated and described above, what is conceptually equivalent, and what can be obviously substituted. Those skilled in the art will appreciate that various adaptations and modifications of the described embodiments can be configured without departing from the scope of the claims. The illustrated embodiments have been set forth only as examples and should not be taken as limiting the invention. It is to be understood that, within the scope of the following claims, the invention may be practiced other than as specifically illustrated and described. 

1. A method of servicing high temperature wells, comprising: securing a cooling chamber onto a wellhead of a high temperature well; raising a tubular member from the high temperature well into the cooling chamber; injecting a cooling fluid into the cooling chamber to cool the hot tubing string prior to handling.
 2. The method of claim 1, wherein the cooling chamber is defined by a stack of spools attached in end to end relation onto the wellhead.
 3. The method of claim 1, wherein the tubular member has a temperature of at least 100° C. prior to entering the cooling chamber.
 4. The method of claim 1, wherein the tubular member is cooled to a temperature of less than 50° C. in the cooling chamber.
 5. The method of claim 1, wherein the tubular member is continuously raised through the cooling chamber.
 6. The method of claim 1, wherein the cooling chamber has a cooling fluid input and a cooling fluid output for circulating cooling fluid through the cooling chamber.
 7. The method of claim 1, wherein injecting the cooling fluid comprises maintaining the pressure of the cooling fluid in the cooling chamber at a pressure that avoids overbalancing the well.
 8. The method of claim 1, wherein the cooling fluid is in direct contact with the tubular member.
 9. The method of claim 1, wherein the tubular member is raised during a snubbing operation. 